Mud pulse telemetry synchronous time averaging system

ABSTRACT

Apparatus and methods for removing the effects of directional drilling systems drilling fluid pulses to allow a MWD mud pulse telemetry system to operate without interference. The methodology is based upon Synchronous Time Averaging (STA). With STA, any pressure fluctuation that is cyclical (or synchronous) with a measurable event can be profiled and subsequently subtracted from a mud pulse telemetry signal. STA functions by placing a strobe in such a manner that the strobe is triggered for each cyclical event. The cyclical event in this disclosure is one (or more) revolution(s) of the drill string. If there is a pressure fluctuation that correlates to that cyclical event, it will be identified by a stable profile of that pressure fluctuation. This pressure profile is then used to remove the cyclical pressure fluctuation from the input mud pulse telemetry signal thereby allowing normal operation of the mud pulse telemetry system.

This disclosure is related to U.S. patent application Ser. No.11/848,328 filed on Aug. 31, 2008, and Ser. No. 12/344,873 filed Dec.28, 2008 both of which are hereby entered into this disclosure byreference.

FIELD OF THE INVENTION

This invention is related to the directional drilling of a wellborehole. More particularly, the invention is related to minimizingadverse effects, in mud pulse telemetry, of drilling fluid pressurefluctuations used to operate directional drilling apparatus.

BACKGROUND

The complex trajectories and multi-target oil wells require precisionplacement of well borehole path and the flexibility to continuallymaintain path control. It is preferred to control or “steer” thedirection or path of the borehole during the drilling operation usingmeasurement-while-drilling (MWD) methodology. It is further preferred tocontrol the path rapidly during the drilling operation at any depth andtarget as the borehole is advanced by the drilling operation. Inaddition, it is preferred to alter the path of the borehole whilemaintaining rotation of the drill string, and to simultaneouslytelemeter borehole information to the surface of the earth.

Many types of directional steering assemblies, comprising a motordisposed in a housing with an axis displaced from the axis of the drillstring, are known in the prior art. The motor can be a variety of typesincluding electric, or hydraulic. Hydraulic turbine motors are operatedby circulating drilling fluid and are commonly known as a “mud” motors.A rotary bit is attached to a shaft of the motor, and is rotated by theaction of the motor. The axially offset motor housing, commonly referredto as a bent subsection or “bent sub”, provides axial displacement thatcan be used to change the trajectory of the borehole. By rotating thedrill bit with the motor and simultaneously rotating the drill bit withthe drill string, the trajectory or path of the advancing borehole isparallel to the axis of the drill string. By rotating the drill bit withthe motor only, the trajectory of the borehole is deviated from the axisof the drill string. By alternating these two methodologies of drill bitrotation, the path of the borehole can be controlled. While deviatingthe borehole, the non-rotating drill string can cause operationalproblems. More specifically, static friction between the non-rotatingdrill string and the borehole wall creates static friction that impedesdrilling efficiency. A more detailed description of directional drillingusing the bent sub concept is disclosed in U.S. Pat. Nos. 3,260,318, and3,841,420, which are herein entered into this disclosure by reference.

Borehole steering assemblies are typically disposed near the drill bit,which terminates the lower or “down hole” end of a drill string. Inorder to obtain the desired real time directional control, it ispreferred to operate the steering device remotely from the surface ofthe earth. This requires a two-way telemetry system between the BHA andthe surface of the earth. The most common MWD telemetry system uses mudpulse methodology to transmit data between the BHA and the surface ofthe earth.

Steering systems have been developed that allow controlled boreholesteering while maintaining rotation of the drill string. These systemswill be referred to, in this disclosure, as “directional drillingsystems”. Continuous rotation of the drill string allowed by thesesystems minimizes previously mentioned operational problems resultingfrom static friction between the drill string and the borehole wall.Directional drilling systems alter or perturb one or more drillingparameters during a portion of a revolution of drill string. Thisperiodic perturbation removes a disproportional amount of material fromthe wall of the borehole resulting in a deviation of the borehole path.

Previously referenced U.S. patent application Ser. No. 11/848,328discloses a directional drilling system that periodically increases thebit rotation rate over a predetermined arc of each drill stringrotation. This results in the desired disproportional removal ofborehole wall material thus resulting in borehole deviation in theazimuthal direction of the predetermined arc. The periodic increase inbit rotation is accomplished by periodically increasing the mud flowthrough the mud motor which, in turn, induces a pressure pulse in thestand pipe of the drilling rig.

Previously referenced U.S. patent application Ser. No. 12/344,873discloses another type of directional drilling system that periodicallyincreases the rate of penetration of the bit over a predetermined arc ofeach drill string rotation. This again results in the desireddisproportional removal of borehole wall material thus resulting inborehole deviation in the azimuthal direction of the predetermined arc.The periodic increase in rate of penetration is again accomplished byperiodically increasing the mud flow as the bit rotates through thepredetermined arc, and again results in a pressure pulse in the standpipe.

As mentioned previously, it is highly advantageous to control adirectional drilling operation in real time from the surface of theearth. In order to obtain the desired real time directional control, atwo-way telemetry system between the BHA and the surface of the earth isrequired, and the most common MWD telemetry system is a mud pulsesystem. Data from downhole sensors and from surface commands are encodedfor transmission by varying the pressure or “pulsing” the pressure ofthe drilling mud column. These pressure pulses are subsequently decodedto extract transmitted data.

As mentioned previously, the above described directional drillingsystems are also controlled by drilling mud pressure pulses, with thesepressure pulses resulting in drilling fluid standpipe pressurefluctuations. The steering system pressure fluctuations will typicallyoccur once per revolution of the drill string, but steering systems canuse multiple periodic pressure fluctuations per revolution. Drillingfluid pressure variations caused by the steering system interfere withpressure variations induced by the mud pulse telemetry system. It is,therefore, necessary to remove the effects of periodic steering systempulses to allow the mud pulse telemetry system to operate properly.

SUMMARY OF THE INVENTION

This invention comprises apparatus and methods for removing the effectsof directional drilling systems drilling fluid pulses to allow a MWD mudpulse telemetry system to operate without interference. The methodologyis based upon Synchronous Time Averaging (STA) which has been used toremove cyclical (or synchronous) “noise” in electromagnetic telemetrysystem as disclosed in U.S. Pat. No. 7,609,169, which is herein enteredinto this disclosure by reference.

With STA, any pressure fluctuation that is cyclical (or synchronous)with a measurable event can be profiled and subsequently subtracted froma mud pulse telemetry signal. STA functions by placing a strobe in sucha manner that the strobe is triggered for each cyclical event. Thecyclical event in this disclosure is one (or more) revolution(s) of thedrill string. If there is a pressure fluctuation that correlates to thatcyclical event, it will be identified by a stable profile of thatpressure fluctuation. This pressure profile is then used to remove thecyclical pressure fluctuation from the mud pulse telemetry signalthereby allowing normal operation of the mud pulse telemetry system.

BRIEF DESCRIPTION OF THE DRAWINGS

The manner in which the above recited features and advantages, brieflysummarized above, are obtained can be understood in detail by referenceto the embodiments illustrated in the appended drawings.

FIG. 1 illustrates a MWD system comprising a directional drilling systemand a synchronous time averaging system to eliminate steering pressurefluctuations at the surface;

FIG. 2 a depicts a strobe increment of 360 degrees;

FIG. 2 b depicts strobe increments of 90 degrees;

FIG. 2 c depicts a strobe increment of 720 degrees;

FIG. 3 is a conceptual flow chart of one embodiment of STA system forminimizing cyclical noise in a mud pulse telemetry system;

FIG. 4 a is a plot of pressure representing a composite signal Rmeasured over a single strobe increment for one revolution of the drillstring;

FIG. 4 b is the plot of a sum of pressures measured over a plurality ofstrobe increments;

FIG. 4 c shows a normalized plot of a cyclical pulse used to operate adirectional drilling system; and

FIG. 4 d shows a mud pulse telemetry signal from which the directionaldrilling system pulse has been removed.

DETAILED DESCRIPTION OF THE PREFERRED EMBODIMENTS

A preferred embodiment of this invention comprises apparatus and methodsfor removing the effects of directional drilling system drilling fluidpulses to allow a MWD mud pulse telemetry system to operate withoutinterference. The methodology is based upon Synchronous Time Averaging(STA) techniques, although the same methodology can be used insynchronous rotational arc averaging as will be subsequentlyillustrated.

Synchronous time averaging is used to identify cyclical noise in mudpulse telemetry response. This telemetry response, which comprises a“signal” component and a “noise” component, will hereafter be referredas the “composite” signal. The signal component typically representsresponse data from one or more sensors disposed within a boreholeassembly (BHA), or data transmitted from the surface to the BHA. Thenoise component can represent any type of cyclical or synchronous noise.In this disclosure, the noise component represents one or more cyclicalpressure pulses used in previously defined directional drilling systems.A strobe is triggered by a cooperating trigger, responsive to astimulus, to record during a predetermined “strobe increment”, aplurality of “increment composite noise signals”. The stimulus can be aswitch, reflector, magnet, protrusion, indention, time signal, or anysuitable means to operate the trigger and cooperating strobe. Theseincrement composite noise signals are algebraically summed Any noncyclical pressure pulse components (such as random pulses representingBHA sensor responses) occurring during the strobe increment willapproach a constant value in the summing operation. Any cyclical noiseoccurring during the strobe increment and in synchronization with thestrobe increment (such as pressure pulses used in directional drillingsystems) will be emphasized by the algebraic summing. Thetrigger-strobe-summing methodology produces a signature or “picture” ofany cyclical noise component occurring synchronously with the strobeincrement. This noise component is then combined with the measuredcomposite signal to remove, or to at least minimize, cyclical noiseallowing the mud pulse telemetry system to operate optimally.

As mentioned above, the technique is not limited to time averaging.Strobe increments can be defined in units of degrees of an arc as wellas an increment of time. In the former case, the process would actuallycomprise “arc” averaging rather than “time” averaging. For purposes ofdiscussion, the averaging process will be generally referred to as STAalthough arc averaging will be used to conceptually illustrate thesystem.

The directional drilling system exemplified by U.S. patent applicationSer. No. 11/843,382 utilizes one or more pressure variations perrevolution of the drill string. In view of this embodiment, the strobeand cooperating trigger are controlled by the rotation of the rotarytable. More specifically, the strobe increment is initiated andterminated by the rotational passage of stimuli comprising predeterminedazimuth points on the rotary table. In this embodiment, the strobeincrement is in degrees, and can comprise a partial arc of the rotarytable or even multiple rotations of the rotary table. As an example, thestrobe increment can be a single rotation of the rotary table. For thisexample, the strobe increment is initiated by the trigger at an azimuthθ₁ and terminated at an azimuth θ₂, where θ₂−θ₁=360 degrees. Otherstrobe increments are applicable as will be illustrated in a subsequentsection of this disclosure.

Attention is directed to FIG. 1, which illustrates a borehole assembly(BHA) 10 suspended in a borehole 29 defined by a wall 51 and penetratingearth formation 36. The upper end of the BHA 10 is operationallyconnected to a lower end of a drill pipe 33 by means of a suitableconnector 20. The upper end of the drill pipe 33 is operationallyconnected to a rotary drilling rig, which is well known in the art andrepresented conceptually at 31. Elements of the steering apparatus aredisposed within a bent sub 16 of the BHA 10. More specifically, a rotarydrill bit 18 is operationally connected to a mud motor 14 by a shaft 17.The mud motor 14 is disposed within a bent sub 16.

Again referring to FIG. 1, the BHA 10 also comprises an auxiliary sensorsection 22, a power supply section 24, an electronics section 26, and adownhole telemetry section 28. The auxiliary sensor section 22 typicallycomprises directional sensors such as magnetometers and inclinometersthat can be used to indicate the orientation of the BHA 10 within theborehole 29. This information, in turn, is used in defining the boreholetrajectory path of the borehole. The auxiliary sensor section 22 canalso comprise other sensors used in Measurement-While-Drilling (MWD) andLogging-While-Drilling (LWD) operations including, but not limited to,sensors responsive to gamma radiation, neutron radiation andelectromagnetic fields. The electronics section 26 comprises electroniccircuitry to operate and control other elements within the BHA 10. Theelectronics section 26 preferably comprise downhole memory (not shown)for storing directional drilling parameters, measurements made by thesensor section, and directional drilling operating systems. Theelectronic section 26 also preferably comprises a downhole processor tocontrol elements comprising the BHA 10 and to process variousmeasurement and telemetry data. Elements within the BHA 10 are incommunication with the surface 45 of the earth via the downholetelemetry section 28. The downhole telemetry section 28 receives andtransmits data to a surface telemetry section 39. The telemetry path isillustrated conceptually by the broken line 30. A power supply section24 supplies electrical power necessary to operate the other elementswithin the BHA 10. The power is typically supplied by batteries.

Once again referring to FIG. 1, drilling fluid or drilling “mud” iscirculated by the mud system 32 from the surface 45 downward through thedrill string comprising the drill pipe 33 and BHA 10, exits through thedrill bit 18, and returns to the surface via the borehole-drill stringannulus. The drilling fluid system is well known in the art.

FIG. 1 illustrates a trigger 34 and a strobe 38 cooperating with thedrilling rig 31, and more particularly with an element such as therotary table or top drive (neither shown) of the drilling rig. A rotarytable will be used for purposes of illustration and discussion. A“strobe increment” is initiated or “triggered” and subsequentlyterminated by the rotational passage of stimuli comprising predeterminedazimuth points on the rotary table. The stimuli can comprise a switch, areflector, a magnet, or any suitable means to operate the trigger andcooperating strobe. Stimuli configured as azimuth points will beillustrated in detail in FIGS. 2 a-2 c and related discussion. Thesurface telemetry section 39 is connected at 37 to the stand pipe of thedrilling rig, in addition to being connected to the strobe 38, and asurface processor 40. The surface telemetry section 39 receives a“composite” mud pulse telemetry response from the downhole telemetrysection 28. This response comprises a telemetry “signal” componentrepresentative of the response of the sensor package 14 and a “noise”component.

Basic Concept of STA

In the context of this disclosure, the signal represents mud pulsetelemetry pulses and the noise component is a series of pressure pulsesused to activate a directional drilling system. The composite telemetrysystem responses are received at the surface by the surface telemetrysection 39. These composite signals are measured during the plurality ofstrobe increments and algebraically summed and stored in the processor40. As mentioned above, any non cyclical pressure pulse components (suchas mud pulses representing BHA sensor responses) occurring during aplurality of strobe increment will sum to a constant or “average”pressure value “A” over a plurality of strobe increment. This is becausethe mud pulse telemetry pulses can occur at any point in the strobeincrement. Conversely, a cyclical noise occurring during thepredetermined strobe increment, and in synchronization with the strobeincrement, will be enhanced by the algebraic summing of the plurality ofstrobe increments. A signature or picture of any cyclical noisecomponent occurring synchronously with the predetermined strobeincrement is obtained preferably by subtracting the average pressurepulse value, preferably within the processor 40. The composite signalfrom a single strobe increment measured by the surface telemetry section39 is simultaneously input directly into the processor 40, as shownconceptually in FIG. 1. The noise signature, normalized to a singlestrobe increment, is then subtracted from the measured composite signal,within the processor 40, to remove cyclical steering system pulse fromthe response of the telemetry system. This results in a mud pulsepressure signal that is free from any cyclical pressure pulses used toactivate a directional drilling system. The mud pulse signal is thenconverted, preferably within the processor 40, into one or moreparameters of interest using responses from sensor within the BHA 10.These results are typically output to a recorder 42 as a function ofdepth within the borehole 29 thereby forming a record of the one or moreparameters in a form commonly known as a “log”.

It should be recalled that the strobe 38 can be triggered by stimuliother than predetermined azimuth points on a rotating element of thedrilling rig including a rotary table, a top drive or protruding drillstring sections. This capability is illustrated conceptually in FIG. 1as an “auxiliary” input 35 cooperating with the trigger 34. As anexample, a clock can be synchronized with the rotation of the drillstring and all processing can be based upon time rather than degrees ofrotation. Stated another way, synchronous time averaging and synchronousarc averaging are conceptually equivalent and will be consideredequivalent in this disclosure.

Data Processing

The synchronous time averaging technique can be implemented using avariety of mathematical formalism with essentially the same end resultsof cyclical noise removal from a composite electromagnetic signal. Thefollowing formalism is, therefore, used to illustrate basic concepts,but other mathematical formalisms within the framework of the basicconcepts may be equally effective.

As discussed previously, the telemetered composite pressure pulse signal“R” is represented conceptually by the broken line 30 in FIG. 1. Rcomprises a signal component “S” representative of the response of themud telemetry system and a composite noise component “N” representingone or more pressure pulses used to operate a directional drillingsystem. Stated mathematically,

R=S+N.  (1)

The strobe is triggered by the cooperating trigger to record, during astrobe increment (in units of time or degrees), a plurality (k-j) ofincrement composite signals “e_(i)”. These composite signals arealgebraically summed initially as

R′=Σ _(i) e _(i).(i=j, . . . ,k)  (2)

If (k-j) is sufficiently large, any non cyclical pressure pulsecomponent (such as mud pulse telemetry pulses “S”) occurring during thestrobe increments will approach an average value “A” in the algebraicsumming of R′. Any cyclical noise component (such as cyclical pulses Nused to activate a directional drilling system) occurring during thestrobe increments, and in synchronization with the strobe increments, isenhanced by the algebraic summing R′. Equation (2) therefore yields acyclical noise component superimposed on an average mud pulse pressurevalue A. The value A is subtracted from R′ to obtain a signature orpicture of the noise component N. That is

N=R′−A  (3)

This cyclical noise component is normalized to a single strobe increment(N′) and then combined with a single strobe increment composite signal Rto determine the mud pulse signal S. For purposes of illustration, asimple subtraction

S=R−N′  (4)

is used to illustrate the determination of S, the mud pulse signalcomponent of interest. The parameter S is, therefore, the telemeteredsignal in a single strobe increment with the cyclical noise removed, andis indicative of the response of the sensor package 14 or datatransmitted from the surface to the BHA 10. A variety of methods can beused to combine the composite signal R and the measure of N includingsemblance and least squares fitting techniques.

The noise normalization of the parameter N is illustrated in more detailin the following section. Degrees rather than time are used to definethe strobe increments. The discussion is equally applicable to strobeincrements defined in time. FIGS. 2 a, 2 b and 2 c illustratesconceptually three strobe increments g, related to determining cyclicalnoise generated by a rotating element of a drilling rig such as a rotarytable. In this case, increment composite signals e_(i) are measuredduring strobe increments “i” defined in units of degrees of rotation.The rotary table (or top drive) is represented conceptually by thecylinder 50 in FIGS. 2 a-2 c. It should be understood that the cylinder50 can also represent essentially any other rotating element providingappropriate strobe increments. In FIG. 2 a, only a single predeterminedazimuth point is shown at 52. The resulting strobe increment g_(i)=360degrees is illustrates conceptually by the arrow 54. In FIG. 2 b two offour predetermined azimuth points are shown at 56 and 58 resulting instrobe increments g_(i)=90 degrees, as partially illustrated by thearrows 62, 64 and 66. In FIG. 2 c, again only a single predeterminedazimuth point is shown at 60, but the strobe increment g, is 720 degreesas indicated by the arrow 68. Strobe increments do not necessarily needto be equal or need to be contiguous. Using the mathematical formalismdiscussed above, the choice of strobe increment necessitates thenormalization of the noise component N expressed mathematically inequation (3). That is

N′=KN,  (5)

where N′ is the normalized noise component discussed above and K is amultiplicative normalization factor. For the strobe increment shown inFIG. 2 a, K=1. For the strobe increments shown in FIG. 2 b, K=4.Finally, for the strobe increment shown in FIG. 2 c, K=0.50.

FIG. 3 is a simplified flow chart illustrating how the concept ofsynchronous time averaging is used in a telemetry system to removecyclical noise and to generate “logs” of parameters of interest as afunction of borehole depth. Increment composite signals e_(i) aremeasured at 70. Preferably, the composite signal R for a single strobeincrement is simultaneously measured at 80. Increment composite signalse_(i) are algebraically summed at 72 according to equation (2). Anormalized noise component N′ is computed at 74 according to equations(3) and (5). The components R and N′ are combined at 76 to determine thesignal component S according to equation (4). The signal component S isthen used to compute at least one parameter of interest at 78 using atelemetered sensor and a predetermined relationship, wherein thepredetermined relationship is preferably resident in the processor 40.The procedure is incremented in depth at 82 and the previously describedsteps are repeated at a new depth.

Results

The results of synchronous time averaging to eliminate noise fromdirectional drilling system mud pressure pulses are illustrated with thefollowing simplified, hypothetical examples.

FIG. 4 a is a plot of pressure (ordinate) representing a compositesignal R measured over a single strobe increment (i.e. K=1) for onerevolution of the drill string. The abscissa can, as discussedpreviously, be in units of time or degrees. The curve 84 representspressure recorded at the surface telemetry section 39. Excursions 86represent data pulses from the mud pulse telemetry system. The excursion88, shown superimposed on a data pulse 86, is a cyclical pressure pulseused to operate a directional drilling system.

The curve 90 of FIG. 4 b represents R′ which is the sum of R over aplurality of strobe increments as defined in equation (2). Over the spanof the strobe increments in which random data pulses fall, the summationapproaches an average pressure A as shown at 91. The cyclical pulse fromthe directional drilling system sums as shown at 88 a. In thisillustration, K=1/(k−j).

FIG. 4 c shows a curve 92 which represents N′=KN=K(R′—A) where theexcursion 88 b represents the directional drilling system pulse 88 bnormalized to a single strobe increment.

Finally curve 84 of FIG. 4 d represents the pressure curve S from whichthe rotary steering pulse 88 b has been subtracted. FIG. 4 d represents,therefore, mud telemetry pulses free from interference from adirectional drilling system pulse.

While the foregoing disclosure is directed toward the preferredembodiments of the invention, the scope of the invention is defined bythe claims, which follow.

What is claimed is:
 1. A MWD mud pulse telemetry system for telemeteringsensor data while operating a directional drilling system, the telemetrysystem comprising: (a) a telemetry section for measuring a compositepressure signal; (b) a trigger sensitive to a stimulus and cooperatingwith a strobe to define a plurality of strobe increments; and (c) aprocessor cooperating with said telemetry section (i) to algebraicallysum increment composite pressure pulse signals measured during saidplurality of strobe increments to define a cyclical pressure pulsecomponent related to said directional drilling system, and (ii) tocombine said cyclical pressure pulse component with said compositesignal to obtain a mud pulse telemetry signal component.
 2. The mudpulse telemetry system of claim 1 wherein said stimulus comprises apredetermined azimuth point on a rotating element.
 3. The mud pulsetelemetry system of claim 1 wherein said stimulus comprises a signalgenerated by a clock.
 4. A method for mud pulse telemetering sensor datawhile operating a directional drilling system, the method comprising:(a) measuring a composite pressure signal with a telemetry section; (b)defining a plurality of strobe increments with a trigger sensitive to astimulus and cooperating with a strobe; and (c) within a processorcooperating with said telemetry section (i) algebraically summingincrement composite pressure pulse signals measured during saidplurality of strobe increments to define a cyclical pressure pulsecomponent related to said directional drilling system, and (ii)combining said cyclical pressure pulse component with said compositesignal to obtain a mud pulse telemetry signal component.
 5. The methodof claim 4 wherein said stimulus comprises a predetermined azimuth pointon a rotating element.
 6. The mud pulse telemetry system of claim 4wherein said stimulus comprises a signal generated by a clock.
 7. A MWDlogging system comprising: (a) a directional drilling system; (a) adownhole mud pulse telemetry section for transmitting a signal componentfrom a downhole sensor; (b) a surface mud pulse telemetry section formeasuring a composite signal comprising said signal component; (c) atrigger responsive to an azimuth point on a rotating element andcooperating with a strobe to define a plurality of strobe increments;and (d) a processor cooperating with said surface mud pulse telemetrysection (i) to algebraically sum increment composite signals measuredduring said plurality of strobe increments to define a cyclical pulsecomponent used to operate said directional drilling system, and (ii) tocombine said cyclical pulse component with said composite signal toobtain said signal component.
 8. The logging system of claim 7 whereinsaid cyclical pulse component is normalized as a function of saiddefinition of said plurality of said strobe increments.
 9. The loggingsystem of claim 7 further comprising a predetermined relationship forconverting said signal component into a parameter of interest.
 10. Thelogging system of claim 9 further comprising a recorder cooperating withsaid processor to generate a log of said parameter of interest.
 11. Thelogging system of claim 7 wherein said directional drilling systemcomprises: (a) a bent sub cooperating with a drill string and drill bit;and (b) a mud motor disposed within said bent sub; wherein (i) saiddrill string and said mud motor are operationally connected to saiddrill bit to operate said drill bit independent of rotation of saiddrill string, (ii) said cyclical pulse component is used vary therotational speed of said drill bit, and (iii) said borehole is deviatedby said periodic variation of said rotary speed of said drill bit.
 12. AMWD logging method comprising: (a) providing a directional drillingsystem; (a) transmitting a signal component from a downhole sensor witha downhole mud pulse telemetry section; (b) measuring a composite signalcomprising said signal component with a surface mud pulse telemetrysection; (c) defining a plurality of strobe increments with a triggerresponsive to an azimuth point on a rotating element and cooperatingwith a strobe; and (d) with a processor cooperating with said surfacemud pulse telemetry section (i) summing algebraically incrementcomposite signals measured during said plurality of strobe increments todefine a cyclical pulse component used to operate said directionaldrilling system, and (ii) combining said cyclical pulse component withsaid composite signal to obtain said signal component.
 13. The method ofclaim 12 further comprising normalizing said cyclical pulse component asa function of said definition of said plurality of said strobeincrements.
 14. The method of claim 12 further comprising convertingsaid signal component into a parameter of interest with a predeterminedrelationship.
 15. The method of claim 14 further comprising generating alog of said parameter of interest with a recorder cooperating with saidprocessor.
 16. The method of claim 12 wherein said directional drillingsystem comprises: (a) a bent sub cooperating with a drill string anddrill bit; and (b) a mud motor disposed within said bent sub; wherein(i) said drill string and said mud motor are operationally connected tosaid drill bit to operate said drill bit independent of rotation of saiddrill string, (ii) said cyclical pulse component is used vary therotational speed of said drill bit, and (iii) said borehole is deviatedby said periodic variation of said rotary speed of said drill bit.